Drilling rigs and workover rigs are utilized to run drill pipes, production pipes or casings into wellbores during the drilling or servicing operations. Such rigs are expensive and the drilling and service operations are time-consuming. To reduce or minimize the time and expense involved in using jointed pipes or jointed tubing, operators often use coiled-tubing instead to perform drilling and/or workover operations.
During the early applications of coiled-tubings, relatively small coiled tubings (typically approximately one inch in outer diameter) were used. Use of a small diameter coiled-tubing limits the amount of fluid that can be injected downhole, the amount of compression force that can be transmitted through the coiled-tubing to the bottomhole assembly, the amount of tension that can be placed on the coiled-tubing, the amount of torque that the tubing can withstand, type and weight of the tools that can be utilized to perform drilling or servicing operations, and the length of the tubing that can be used.
Due to improvements in the materials used for making the coiled-tubings and improvements in the tubing-handling equipment, coiled-tubings of varying sizes are now commonly used to perform many functions previously performed by drill pipes or jointed-tubulars. Due to the low cost of operating coiled-tubings, the flexibility of its use and the continued increase in the drilling of complex wellbores, such as multi-lateral wellbores, highly deviated wellbores and the more recent development of contoured wellbores, the use of coiled-tubings has been steadily increasing.
However, the injectors and the equipment for handling tubings from reels to injectors are still typically designed to run a specific tubing size. Most of the operations of the prior art injectors, tubing reels and wellhead equipment are manually performed by operators who respond to visual gauges to operate a variety of control valves that direct hydraulic power to different elements of such injectors, tubing reels and the wellhead equipment. The prior art injectors are not designed to allow for the passage of relatively large diameter bottom hole assemblies therethrough. Thus, in order to perform a drilling or workover operation with a relatively large diameter bottom hole assembly attached to the lower end of a relatively small outer diameter tubing, the bottomhole assembly is either attached below the injector prior to placing the injector on the subsea wellhead or it is attached below the tubing after the tubing has passed through the injector. Such a process is relatively cumbersome and can be unsafe.
For land operations, the injector head is typically placed on the wellhead equipment. To attach a bottomhole assembly such as a drilling assembly, the injector head is removed from the wellhead equipment to insert the bottomhole assembly into the wellhead equipment. Additionally, systems having vertically-movable injector head and gooseneck, which allow the operator to connect and disconnect the bottomhole assembly to the tubing on a working platform have also been used.
For land operations, the prior art tubing injection systems still require moving the injector head from its operating position whenever a relatively larger diameter bottomhole assembly is to be inserted into a wellbore through the wellhead equipment. These systems also do not provide an injector head that allows the passage of both tubings and bottomhole assemblies of a variety of sizes to pass through the injector head when the bottomhole assembly is already connected to the tubing.
An additional drawback of the prior art injector heads is that they bite into the coiled tubing and frequently induce into the coiled tubing excessive stress resulting in reduced tubing life or damaged tubing. In some cases, the damaged tubing requires the operators to cease the operations and replace the tubing, which can cost several thousand dollars of down time.
It is, therefore, desirable to have an injector head that allows the passage of a wide range of bottomhole assemblies through the injector head and insert and remove coiled tubings of various sizes into and from the wellbore without the necessity of removing the injector head. It is further desirable to have an injector head which can securely grip the tubings without inducing undue radial stress into the tubings or damaging the tubings.
In the prior art systems, the tubing is typically unwound from a reel and passed over a gooseneck, which is a rigid structure of a relatively short radius. Such goosenecks impart great stress onto the tubing when the tubing is passed from a tubing reel into the injector head. Also, the prior art systems utilize manual methods for controlling various operations of the tubing injection systems. Such manual methods are imprecise, can induce excessive stress in the tubing and are labor-intensive.
For offshore operations, floating vessels, such as ships, semi-submersible platforms, and fixed offshore platforms, such as jack-up rigs, are utilized for drilling, completing and servicing subsea wellbores and for performing workover and other post-drilling services. Most of the coiled-tubing injection systems are designed for use with land rigs. Relatively little progress has been made in developing coiled-tubing injection systems for subsea applications, especially from floating vessels or rigs. Coiled-tubing operations from floating rigs pose unique problems because of the constant motion of the vessel. Additionally, injector heads are not permanently installed on subsea wellhead because prior art injectors require attaching the bottom hole assemblies, such as drilling assemblies, typically having substantially greater outside diameters compared to the tubing, after the tubing has passed through the injector head. Additionally, prior art systems do not provide methods for transporting a bottomhole assembly attached to a tubing end between the wellhead and the vessel. Prior art systems also do not provide underwater tubing injection systems that are automatically operated from the surface. Due to the corrosive nature of sea water, electrical sensors are typically not used in connection with under-water injection heads. Also, prior art underwater injector systems are not efficient, do not allow for the automatic control of the injectors and typically require attaching the bottom hole assembly below the underwater injector prior to the placement of the injector on the wellhead.
U.S. Pat. No. 5,002,130, issued to Laky, discloses an injector placed underwater on the wellhead for injecting a tubing into the wellbore. To place the injector on the wellhead, the coiled-tubing is securely held into the injector. The injector is then lowered from the offshore platform into the sea by the coiled-tubing until it reaches the wellhead. The weight of the injector is used to lower it to the wellhead. To keep the injector from coming in contact with the sea water, the injector is encased in an enclosure. Water in the enclosure is displaced by a gas. Gas injection devices are provided for continuously injecting the gas into the enclosure to replace any gas that may leak during operations. Such a system requires gas injection equipment and other control equipment for ensuring continued supply of gas into the enclosure during the entire length of the operation being performed, which can be expensive and requires installing additional equipment underwater, such as the gas injection devices. The same results can be obtained by sealing selected elements of the injector, such as the bearings, drive mechanisms and motors, as provided by the present invention.
In addition to the above-noted deficiencies of the prior art systems, operations of the injector head and the wellhead equipment, such as the blowout preventor, are generally manually controlled by several operators. These operators adjust a variety of hydraulic control valves to adjust various operating parameters, such as the gripping pressure applied by the injector head on the tubing, the injector head speed, the back-tension on the tubing at the reel, and the operation of the blow-out-preventor equipment (BOP). Some systems require several operators who must be stationed at different locations at the rig to control the various operations of the injector head, reel and the wellhead equipment. Such manually controlled operations are imprecise, labor intensive, relatively inefficient and detrimental to the long life of the equipment, especially the coiled tubing.
It is, therefore, highly desirable to have a tubing injection system wherein certain operating parameters relating to the various equipment, such as the injector head, tubing reel and the wellhead equipment, are remotely and automatically controlled to provide a more efficient and safer rig operations. It is further desirable to provide a safe working area away from the injector head for the operator to connect and disconnect the bottomhole equipment to the tubing and to pass such equipment through the injector head without moving the injector head or the gooseneck.
It is also highly desirable to have a tubing handling system for subsea use that includes a permanently installed (for the duration of the work to be performed) injector at the subsea wellhead that can be opened to allow the passage of bottomhole assemblies therethrough and move the tubing through the wellbore. It is further desirable to remotely control the operation of such subsea injector to provide a more efficient and safe operation, including automatically adjusting the gripping force on the tubing to a desired value and shutting down the injection system and/or activating appropriate alarms if an unsafe condition, such a free falling tubing, is detected.
The present invention addresses the above-noted deficiencies of prior art land and subsea tubing handling systems and provides tubing injection systems, wherein a novel injector placed on the subsea wellhead or at the surface allows for the passage of relatively large diameter bottomhole assemblies therethrough. The tubing injection systems automatically control the operation of the injector, whether installed at the surface or underwater, and other elements of the tubing injection system. The subsea system further includes a secondary surface injector for transporting the bottomhole assemblies attached to the tubing from the vessel to the subsea injector.